Field of the Invention
The present invention is in the field of oil and gas refining and, particularly, the processing of sour natural gas and/or sour or acid gas by-products of an oil or natural gas refinery by a primary gas treatment facility and more particularly, in utilizing an auxiliary gas treatment system to manage flare emissions for mitigation of pollution and compliance with emission limitations.
Description of Related Art
When crude oil or sour natural gas is extracted from the ground, it must be refined to deliver a commercially distributable fuel and/or other products. Oil and gas refining typically involves several steps including the generation or production of waste gas and safe disposal of the same. If crude oil or harvested natural gas contains significant amounts of sulfur compounds, it is called “sour oil” or “sour gas.” The sulfur compounds and other contaminants must be removed from the commercially produced products and the waste gases then include these unwanted contaminants. Many refineries flare off combustible waste gases because they are too volatile to store and transport for future use, and because flaring is a highly reliable methodology for safe disposal of the waste gas. However, because the waste gas may contain harmful or unwanted contaminants, treatment of the waste gas often includes removing contaminants to render them more suitable for disposal or otherwise useful. Common waste gas contaminants include sulfur compounds, primarily hydrogen sulfide, and carbon dioxide.
Waste gas that includes significant hydrogen sulfide is referred to as “sour gas”. Because waste gases that include hydrogen sulfide and/or carbon dioxide also form corrosive acids when combined with moisture, the more concentrated of these gases are also commonly referred to as “acid gas.” Accordingly, these hydrogen sulfide bearing gases will be referred to collectively herein as “sour gas” throughout this description, and the use of “sour gas” herein is intended to include any gases that include both high and low concentrations of acidic sulfur compounds, carbon dioxide, and/or other contaminants now known or hereafter discovered to behave similarly.
Refineries typically include primary gas treatment facilities which may include treating sour gases in “amine units” or gas sweetening units which produce a stream of acid or sour gas (enriched in hydrogen sulfide) and a stream of desulfurized fuel or product gases, typically hydrocarbons, largely depleted of hydrogen sulfide. These amine-based product gas treating units today are typically upstream of “sulfur recovery facilities” that further treat enriched sour gases prior to disposal. Often, the sulfur recovery facility also includes an amine-based gas treating unit as well serving to treat tail gases. The primary gas treatment facilities, including amine units operate more or less continuously and typically include an absorber, a regeneration system comprising heat exchangers, a reboiler, and a stripping column and normally make use of pumps to continuously circulate solvent back and forth between the absorber and the regeneration system. Such primary gas treatment facilities require power, steam, electricity and other industrial utilities to operate properly. Due to emissions limitations regulating sulfur dioxide and hydrogen sulfide, primary gas treatment facilities also require the continuous, simultaneous availability of a downstream sulfur recovery plant (or equivalent) to process the hydrogen sulfide captured and render it harmless. Primary gas treatment facilities or systems may also be incapable of treating their current supply of sour gas or subject to malfunction. At times, the produced enriched sour gases become suddenly and/or highly contaminated with hydrocarbons or amine or both and therefore, a chemical property of the downstream enriched sour gas product becomes out of specification or has variances which render such sour gas stream suddenly unsuitable for processing in a sulfur recovery plant or other gas treatment facility. Primary gas treatment facilities may also be incapable of processing a supply of sour gas or may malfunction when material properties of the gas are out of specification or include variances in the material properties which render the sour gas produced unsuitable for processing in a sulfur recovery plant or other primary gas treatment facility. Such material properties may include temperature, mass flow of sulfur compounds or other chemicals including hydrocarbons and amines, or any other material property now known or hereafter monitored. Primary gas treatment facilities or systems are sometimes incapable of processing a supply of sour gas when a chemical or material property has variances which suddenly fluctuate from one value to another, even in cases when the overall property may be within the nominal specification of the gas treatment facility or system. For example, a sulfur recovery plant in a gas treatment facility or system may be capable of treating a supply of sour gas contaminated with a range from one-half percent to five percent hydrocarbon content. Nevertheless, such a primary gas treatment facility may be incapable of treating a supply of gas that either (1) exceeds the treatable limit of hydrocarbon concentration of five percent or (2) has excessive variances in the mass flow of hydrocarbon contained in the supply of sour gas even if the hydrocarbon content is under the five percent limit.
Refineries may implement “flare gas recovery systems” if the waste gas is a sour gas in order to treat flare gases prior to being flared, and in order to recover fuel values in the gases. Flare recovery systems generally extract gases from the flare system using compression and subject the compressed sour gases to pretreatment to remove sulfur compounds and other contaminants in order to meet quality or regulatory emissions standards. Such flare gas systems as presently implemented, however, invariably depend on the immediate and simultaneous availability of adequate downstream equipment to (a) selectively remove the sulfur compounds, (b) immediately regenerate the selective reagent, and (c) immediately treat the removed compounds, typically by conversion to elemental sulfur, prior to use of the recovered gases or prior to disposal of the remaining gases to flare. In a few special cases the “recovered” flare gases are treated with non-regenerable reagents (such as caustic soda or ammonia) but these processes and reagents are costly, involve hazardous reagents, and produce hazardous waste stream(s) requiring generally costly disposal.
The sour gas combustible waste gases produced by refineries contain hydrogen sulfide which must be removed due to the highly regulated combustion products produced if hydrogen sulfide is flared without treatment. Hydrogen sulfide itself is malodorous, highly toxic and flammable, and is not readily stored because of its high vapor pressure, variable composition, and the threat it poses as an air-toxic and an explosion hazard. Further, because of transportation, environmental and other safety constraints, it has little or no commercial market, and is not easily stored as a compressed gas or liquefied gas. Accordingly, a supply of sour gas requires immediate processing and continuous treatment in order to prevent potential harmful effects to people and/or the environment due to the hydrogen sulfide.
Flare recovery systems to date have generally been completed by primary gas treatment facilities that receive the stream of the combustible flare recovery gas waste along with sour fuel gases also continuously produced from the continuous operation of the upstream oil or natural gas refinery. These gases are typically desulfurized in the facility's amine gas treating unit(s), and the enriched product sour gas is then sent for immediate processing in the downstream sulfur recovery plant serving the facility. FIG. 1 illustrates an embodiment of a downstream primary sour gas treatment facility 100 that is commonly used in the present industry. Primary sour gas treatment facility 100 receives the enriched sour gas stream from the upstream refinery amine gas treating units 101, such as a fuel gas, natural gas, or other sour gas treatment facility, and sour water units through an influent pipe 102, performs pretreatment if necessary to remove excess hydrocarbons and typically commercially produces elemental sulfur 105 in a Sulfur Recovery Unit (“SRU”) 104 as a by-product of the treatment and processing of the sour gas. In its elemental foam, sulfur 105 is a non-toxic liquid and solid material which is readily stored, transported, and consumed in vast quantities in the production of other products for which there is an adequate market, such as fertilizer and other consumer and industrial products.
SRU 104 may and generally does utilize the well-known multi-stage Claus recovery process to partially oxidize the hydrogen sulfide in the sour gas and remove up to around ninety-seven percent (97%) of the sulfur initially present in the sour gas. The Claus process typically utilizes a thermal reactor stage and two or more catalytic reactor stages in series, and (when receiving good quality gas feed) recovers the elemental sulfur as a molten liquid of high purity. Both the process and the product quality can be damaged if the feed gases become highly contaminated with hydrocarbons in a malfunction. While highly efficient, the Claus process does not remove all sulfur or sulfur compounds from the sour gas, therefore, the gas exiting SRU 104 is called “tail gas” and includes the remaining hydrogen sulfide, sulfur vapors and mists, other toxic sulfur compounds at low concentrations and other contaminants including carbon dioxide, nitrogen, and water vapor which make up most of the typical tail gas. Thus, the treatment and processing of the influent sour gas also typically involves being output through a pipe 106 and into a complex tail-gas treatment unit 108 to substantially remove the remainder of the sulfur content from the sour gas prior to the depleted tail gas being vented or incinerated. The tail-gas treatment unit 108 is used to minimize the emissions of sulfur dioxide and hydrogen sulfide and to meet current regulatory emissions standards for such SRU's. Further, both the Claus and tail-gas treatment units are highly sensitive to damage by gases with excessive and rapidly changing non-sulfur contamination, such as hydrocarbons.
FIG. 1 also illustrates a general schematic of typical tail-gas treatment unit 108 of a primary sour gas treatment facility 100. The tail gas may be heated by heater 110 to bring it up to a temperature more conducive for reactions. After being heated, the tail gas proceeds through piping 112 to the hydrogenation/hydrolysis reactor 114 wherein most all sulfur and its compounds in the tail gas are converted to hydrogen sulfide through a known catalytic process using hydrogen gas. The tail gas now containing its sulfur content as hydrogen sulfide travels through piping 116 to a condenser 118 which cools the gas to remove water vapor. Recovered water is piped out pipe 120 and may be treated before discharge. At this point, the tail gas treatment unit begins to resemble an amine unit used for treating fuel gases. The cooled, de-watered tail gas flows out of condenser 118 through piping 122 to an absorber 124.
The tail gas travels through absorber 124 wherein the tail gas contacts and reacts with a lean solvent which is known to persons in the art to selectively absorb hydrogen sulfide to remove sulfur from the tail gas. The lean solvent is introduced into absorber 124 through lean solvent inflow pipe 126. The lean solvent is then placed into contact to interact with the tail gas, thereby scrubbing the hydrogen sulfide therefrom. Lean solvents for such purposes are known in the art and commonly used in absorbers in tail gas conversion processes. Such solvents are generally selected to largely reject carbon dioxide absorption in order to prevent carbon dioxide buildup in the overall sulfur recovery scheme. Once the lean solvent reacts with the hydrogen sulfide, it is then in a “rich”, “semi-rich” or “semi-lean” state wherein it contains the hydrogen sulfide removed from the sour gas through absorption, adsorption, dissolution, or due to any other chemical suspension or reaction. Once the hydrogen sulfide is removed from the tail gas, the cleaned gas exits absorber 124 through a vent gas pipe 128 to an incinerator 130 where it is normally oxidized to remove odorous compounds prior to disposal of the cleaned waste gas stream to atmosphere, typically at a stack. The tail-gas treatment unit 108 may include a method to capture the heating capacity of exiting cleaned tail gas to be used as energy in the treatment facility. In some cases, the depleted tail gas is not incinerated and is simply vented.
The rich solvent exits absorber 124 through a rich solvent out pipe 132 and is conveyed to a solvent regenerator 134 wherein the hydrogen sulfide is removed from the rich solvent. The process of regeneration typically includes the rich solvent being preheated by indirect heat exchange with the lean solvent leaving reboiler 136 and/or then processed in a reboiled regenerator 134 where the absorbed sour gases are stripped from the aqueous solvent solution by introduction of heat and/or steam from the reboiler/steam generator 136. The regenerated hydrogen sulfide gas exits the regenerator as an enriched sour gas through return pipe 138 wherein the regenerated sour gas is cooled and conveyed back to be combined with the influent gas in influent line 102 to be re-processed through SRU 104. The regenerated lean solvent returns to absorber 124 through pipe 126 as shown, generally exchanging its heat with incoming rich solvent. The piping and transfer of gas and fluid through the downstream tail-gas treatment unit 108 may be accomplished through a number of piping configurations, valves and/or pumps positioned to move the products and by-products through the system as will be appreciated by a person of skill in the art. There are, of course, other variant tail gas treatment processes, some of which do not involve the production of hydrogen sulfide, or even the production of sulfur, but the majority of installations in the United States use a process similar to the above. In each case, however, these tail gas treatment processes, from time to time, must go offline for repair or to address process upsets, and most are highly complex. In such cases of equipment going offline or to a state of reduced capacity, any excess of the continuous stream of incoming sour gas to the sulfur recovery plant (or its equivalent) has no place to go except to flare.
Tail-gas treatment unit 108 may include a known amine unit. While primary sour gas treatment facility 100 including tail-gas treatment unit 108 is commonly used in the art downstream of a refinery sulfur plant, other amine-based primary gas treatment facilities are also frequently implemented at refineries which function similarly to tail gas treatment unit 108 described above, for example in de-sulfurizing sour fuel gases and generating enriched sour gas feed for a sulfur recovery plant and its associated tail gas treatment unit. In addition to the SRU 104 and tail gas treatment unit 108 of primary sour gas facility 100, the term “primary gas treatment facility” and “primary gas treatment system” as used herein shall also refer to any other amine-based gas treatment facilities or systems now known or hereafter developed to treat sour gases including, but not limited to a sour fuel gas treatment facility or system, a sour natural gas treatment facility system, a primary sour gas treatment system including a sulfur recovery unit, and a tail gas treatment facility.
These known primary gas treatment facilities must be taken off-line, or are forced to shut-down or slow down for periods of time and are temporarily inadequate for the incoming sour gas supply demand for any one of a number of circumstances. As shown in FIG. 1, the method currently used by such gas treatment facilities during such periods of inadequacy is to operate by-pass valve 140 to direct some or all of the influent gas from the upstream refinery through bypass pipe 142 directly to flare tower 130 wherein the sour gas is combusted without being treated and the potentially harmful by-products, sulfur dioxide and any unburned hydrogen sulfide, are emitted into the atmosphere.
These primary sour gas treatment facilities, while well developed, are complex, multistage technologies, typically involving tens of millions of dollars in capital equipment, requiring continuous supplies of utilities, and skillful operation. They are typically subject to strict emission limitations, for example, for the control of sulfur dioxide and hydrogen sulfide emissions. However, much like any mechanical system, the primary sour gas treatment facility equipment requires repair and maintenance which often cannot be carried out while the process is running. Thus, situations inevitably arise, sometimes without notice, in which primary sour gas treatment facility's 100 processing capacity is limited or not available, while upstream sour gas production cannot be simultaneously or instantly halted. Examples of events in which treatment by primary gas treatment facilities may become interrupted include without limitation: power failures, cooling failures, fires, explosions, contaminated feeds unsuitable for processing in the sulfur plant, essential repairs, plugging or fouling of downstream equipment, imbalances between produced gases and downstream capacity, surges, startups, shutdowns, process upsets and so on.
When the upstream facility is still producing and supplying sour gas and the primary sour gas treatment facility is shut-down or limited for any reason, the upstream refinery processes or the primary sour gas sulfur treatment facilities typically address these situations by using one or more of the following techniques: flaring the excess gases, shutdown or curtailment of upstream production, and/or parallel or redundant equipment in the amine units, the sulfur plant and the tail gas plant, and/or emergency power and emergency cooling or both. These methods each have substantial shortcomings, particularly in view of processing economy and stricter environmental standards.
Redundant or excess processing equipment adds to the equipment cost and the equipment complexity, and is an extremely inefficient use of resources because the excess equipment is unused and subject to degradation during normal operation of the primary sour gas treatment facility. Furthermore, redundant equipment simply cannot address cases where the incoming feed becomes so far out of specification that it cannot be safely processed in a Claus plant (or equivalent) or any downstream tail gas treatment unit. Moreover, redundant or excess processing equipment has an increased vulnerability to corrosion and breakdown itself because it is occasionally exposed to the sour gas, but is not constantly used to prevent exposure to oxygen and other corrosive conditions. Sour gas and intermediate compounds from its processing may be extremely corrosive and if the gas and its derivatives are left in the idle equipment, even in trace amounts, and combine with the oxygen in the atmosphere, the result is extremely corrosive. Further, being similarly complicated to the primary treatment process, the redundant or excess processing equipment likely will not be immediately available for instant service when actually needed, particularly for unplanned events such as, for example, malfunction in upstream equipment, a power outage, operator error, or the plugging or fouling of downstream equipment. Such equipment must be carefully started, generally over a period of hours or even days, in order to prevent damage.
Similarly, slowing down or stopping the upstream refinery is slow and very inefficient and unnecessarily exposes the upstream refinery to risks of accidents or some other risk. The start-up and shut-down of the refinery is among the most dangerous of the refinery operations. At that time, the hazardous components are at their most unknown and variable conditions and the process is the most dynamic and uncontrolled and the sour gas produced during start-up or shut-down often have properties and variances that are out of specification for treatment in a primary gas treatment system. Moreover, interfering with the production of the upstream refinery causes variations in production that have adverse financial and product quality consequences on the producer and, potentially, on the consuming public and should be avoided whenever possible.
If a primary gas treatment facility does not have redundant downstream processing equipment instantly available and the upstream refinery does not instantly shutdown, then the flaring of excess hydrogen sulfide containing gases necessarily occurs whenever there is an imbalance between the upstream demand and the downstream processing capability. Flaring technology has been safely used for over one-hundred years to burn off refining by-products and is the industry standard because it is highly effective, simple, and highly immune to damage and overload. Further, flaring is not necessarily dependent on any other utilities, such as electricity or cooling. However, even when only used in an emergency situation, flaring diverted sour gas has raised increased environmental regulation scrutiny due to the associated emissions of sulfur dioxide and hydrogen sulfide. Further, the release of sulfur dioxide into the air, even in necessary amounts during emergencies is being increasingly restricted, foreclosing responsible use of flaring for handling sour gases. Governmental regulations increasingly restrict the emissions of sulfur dioxide and hydrogen sulfide, including those arising in emergency flaring.
Thus, there is a need in the art for an auxiliary sour gas treatment system to be used separately from or integrated into a primary sour gas treatment facility that eliminates flaring untreated acid waste gas whenever there is an imbalance between the demand of the sour gas supply and the primary sour gas treatment facility's processing capability for compliance with emission limitations. This includes overloading of the gas treatment facility at peak production times, a sour gas supply out of specification, a shut-down of the downstream plant for repairs, controlled startup following repairs, outages in regeneration equipment and/or downstream (sulfur) recovery equipment, or an emergency shut-down to a malfunction, power outage or other interruption in utilities. A simple and cost-effective auxiliary treatment system is particularly needed when this imbalance is of a short term nature and finite in duration, as is often the case.